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Louisiana Task Force Approves State’s First-Ever Climate Acton Plan

February 20, 2022

by Peter Maloney
APPA News
February 20, 2022

A Louisiana task force has approved and presented to the state’s governor a Climate Action Plan that would set a goal of achieving zero net greenhouse gas (GHG) emissions by 2050.

The Climate Action Plan recently unanimously approved by Gov. John Bel Edwards’ Climate Initiatives Task Force has three priority policy pillars: renewable electricity generation, industrial electrification, and industrial fuel switching to low- and no-carbon hydrogen.

The policies were tailored to reflect an updated inventory of the state’s greenhouse gas inventory, which was part of the action plan. The inventory showed that 64 percent of Louisiana’s GHG emissions are concentrated in the industrial sector, driven primarily by the state’s refining, chemical manufacturing, and natural gas processing facilities. Another 19 percent of the state’s overall GHG emissions come from the transportation sector, and 13 percent result from electric power generation.

The interim goals of the Climate Action Plan set several goals for renewable resource implementation, including 100 percent renewable or clean energy by 2035 with at least 80 percent from renewable sources, 5 gigawatts (GW) of offshore wind generation by 2035, 100 megawatts (MW) of energy storage by 2030, and a 30 percent increase in transmission infrastructure by 2030 and a 100 percent increase by 2050.

Some elements of the Climate Action Plan would require legislative action, such as the reinstatement of incentives for the installation of renewable resources and energy storage to encourage the purchasing of renewable power.

Other elements of the plan would require action on the part of the state’s Public Service Commission, such as a review of net metering policies and a determination of the best mechanisms for third parties to sell power back to the grid in order to encourage the generation of renewable power.

The industrial emissions reduction aspects of the plan call for “electrification to the extent practicable” and fuel and feedstock switching to alternative sources such as hydrogen and also provides support for research on carbon capture technologies.

The Climate Action Plan also charts a course for addressing the “persistent and complex” challenge of methane emitted from oil and gas infrastructure, particularly orphaned wells.

The transportation and built environment aspects of the plan calls for the installation of 250 electric vehicle charging stations per 100,000 residents by 2050. The plan also calls for legislation for energy efficiency and code upgrades that would require minimum efficiency levels in buildings.

The Climate Action Plan, a first for Louisiana and the first among the state’s neighbors on the Gulf of Mexico, was designed to align Louisiana with pledges made under the United Nation’s 2015 Paris Agreement and with goals set by the federal government, 25 other states, and hundreds of private companies.

Bioenergy, Carbon Capture Are Key To GHG Reduction Strategies: Report

February 20, 2022

by Peter Maloney
APPA News
February 20, 2022

While currently limited, the bioenergy with carbon capture and storage (BECCS) industry has great potential and could play a key role in significant emissions reductions across the economy, according to a new report from the Energy Futures Initiative.

The report, Surveying the BECCS Landscape, analyzes the scientific and research literature on BECCS and its potential to remove greenhouse gas (GHG) emissions from the atmosphere.

BECCS projects can run the gamut from a biomass-fueled power plant to a project that captures carbon dioxide (CO2) and injects it into wells for enhanced oil recovery. The authors of the report, however, say BECCS systems share common features such as a biomass feedstock, biomass-to-energy conversion, carbon capture, and carbon storage or utilization. They noted, however, there is little consensus on precisely which biomass feedstocks, conversion techniques, and carbon capture approaches should be labeled as BECCS and whether a project must be carbon-neutral or carbon-negative to qualify as BECCS.

Definitions aside, the report argues that BECCS has the potential to help with emissions reductions in numerous sectors of the economy, such as agriculture, forestry, electricity, waste, and industry and particularly sectors that are hard to decarbonize, such as heavy industry, aviation, and agriculture.

Nonetheless, there are only a handful of BECCS projects deployed globally, and they are mostly pilot- or demonstration-scale projects that capture less than 400 kilotons (kt) of CO2 a year for enhanced oil recovery or other uses, the report noted.

Without BECCS it will be difficult or even impossible to reach net negative GHG emissions, the report says, noting that the United Nations’ Intergovernmental Panel on Climate Change includes BECCS in its GHG reduction scenarios.

Among the report’s key findings, the authors noted that modeling studies project the need for massive global BECCS deployment, up to 8 gigatons of CO2 per year by 2050. That potential could be hard to achieve, however, because of limited feedstock availability, access to CO2 infrastructure and disposition options, and socioeconomic or environmental limitations, they said.

And while the BECCS industry is currently limited in the United States to only five operating projects, the country has “several characteristics that make it suitable for BECCS deployment including well-established relevant industries (e.g., biofuels, biopower, forestry, agriculture, wood pellet production, and pulp and paper), significant natural resources (e.g., biomass and geologic storage), and growing policy support (e.g., the newly extended 45Q tax credit and the Energy Act of 2020),” the report said.

To reach that potential, expanded biomass supply chains and CO2 infrastructure are needed to support a national BECCS industry, the report said.

And while BECCS pathways face opposition because of environmental justice concerns or because the technologies are often seen as “false solutions” to addressing climate change, the report noted that BECCS pathways can present rural economic development opportunities.

BECCS is beginning to appear more often in legislation, public policies, and federal programs, the report said, but “these efforts are not commensurate with a scale-up to a gigaton-scale industry.”

“Growing the BECCS industry enough to have a meaningful impact on U.S. emissions will require support and expertise from multiple agencies, making federal interagency collaboration paramount,” the report’s authors said.

CMUA Policy Paper Assesses, Advises on California’s 2045 Clean Energy Goal

February 20, 2022

by Peter Maloney
APPA News
February 20, 2022

Reliability and affordability will be key to California’s efforts to greenhouse gas (GHG) emissions, according to a new policy paper by the California Municipal Utilities Association (CMUA).

Reaching California’s target of 100 percent clean energy by 2045 rests on four principles: predictability, reliability, affordability, and flexibility, the paper, Powering California’s Future with Clean, Affordable and Reliable Energy: Four Principles for Success, argues.

“Part of our mission is to be a thought leader,” Barry Moline, executive director of CMUA, said. “We have a responsibility to put good ideas in front of policy makers and to set standards going forward. We are part of the solution and need to be part of the solution in a particular way.”

California’s utilities have already made significant progress toward the state’s goals by reducing electric sector GHG emissions by at least 40 percent since 2006. Much of that progress can be ascribed to collaborating with the state on the many laws and agencies that govern and regulate the state’s energy sector and promote initiatives aimed at mitigating climate change.

In addition to SB 100, also known as the 100 Percent Clean Energy Act of 2018 – a seminal law that put California on the path to 100% clean energy by 2045 – two laws were passed in 2021 that supplement the SB 100 planning process. And, California has a full-time legislature, that annually proposes a continual parade of new bills. Last year, 2,400 bills were introduced in the state’s legislature with about 140 of them related to energy, a “pretty average number,” Patrick Welch, CMUA senior director of energy policy and strategy and author of the paper, said.

“When the laws and regulations driving renewable and clean energy procurement are constantly changing, it can harm the financial stability of utilities, causes project delays, jeopardizes climate progress, and impose costs on California utility customers,” the paper said.

“We have strong foundational clean energy laws in California with a robust planning process to pave the road to 100% clean energy. If legislators want to create new laws, we think they should be looking at removing barriers, and should be cautious about imposing new requirements that change the rules of the game,” Welch said.

“Predictability doesn’t mean just saying, ‘No,’” Moline said. “We want new laws that help achieve goals already established.”

The paper also advises on challenges that the sate’s clean energy goals will present to affordability. Meeting the state’s 2045 target will require more than doubling the energy resources on the grid, including nearly 120 gigawatts (GW) of new clean resources, including utility-scale solar, batteries, and wind farms, and potentially up to 173 GW of new resources.

That “record-breaking” pace of resource expansion over the next 25 years “will come at a cost” of about an additional $4.6 billion annually by 2045 charged to California ratepayers, the paper said, adding that eliminating all fossil-fuel combustion for electricity generation would cost another $8 billion every year.

Citing a Legislative Analyst’s Office report from 2017, the CMUA paper noted that electric rates in California were about 50% higher than the national average. The are multiple factors contributed to those rates, including how fixed costs are recovered, declining energy consumption due to energy efficiency implementation, and state mandates such as the state’s renewable portfolio standard and its carbon dioxide cap-and-trade program.

CMUA also cited a February 2021 paper released by the California Public Utilities Commission that found that rate and bill increases could make other climate policy goals more difficult to achieve.

And a joint agency report to the governor, said that 2021-2030 overall bundled residential rate forecasts for California’s three large investor-owned utilities are expected to grow at a pace that exceeds inflation for many years in the coming decade.

Those concerns could be compounded as the state turns to electrification to address emissions reductions in other parts of the economy, such as the transportation sector, Moline said. “If rates ratchet up too much, people are not going to want to switch to those technologies,” such as adopting electric vehicles. If legislators and regulators are not paying attention to those problems, we want to make sure they are on the marquee,” Moline said.

And while public power utilities such as the Los Angeles Department of Water and Power (LADWP), the Sacramento Municipal Utility District and the Glendale Department of Water & Power have made progress toward reducing GHG emissions, the paper said that they also face more challenges as the level of renewable and clean resources on their systems grow, particularly as they approach the last 10 percent of the 100 percent goal.

“It will be particularly important, as utilities meet their  2030, 60 percent renewable energy goals and continue to plan for 100% clean energy by 2045, for there to be latitude and flexibility in resource selection,” Welch said. “As we approach those thresholds, having a narrow focus doesn’t work from a reliability or cost standpoint.”

“A lot of low hanging fruit has been picked,” Moline said. So, it will be important to have flexibility with respect to the “buckets” that currently specify acceptable types of renewable resources. “Are we stuck in some old school idea or are we open to innovating?” he asked, noting that CMUA is advocating for hydropower to be counted toward meeting emission reduction goals above the 60 percent threshold.

In short, the policy paper should serve as a guideline for lawmakers and regulators, Moline said. The clean energy principles in the paper will move the state toward its goals “faster and with a solid foundation of outstanding service to the people of California,” he said.

APPA-Funded Study Provides Heat Pump Water Heater Guidebook and Calculator Tool for Public Power Utilities

February 17, 2022

by Vanessa Nikolic
APPA News
February 17, 2022

A new American Public Power Association-funded study has resulted in the development of a new guidebook and calculator tool which will be useful for public power utilities interested in adopting grid-interactive heat pump water heaters (HPWHs). 

American Municipal Power, Inc. (AMP), a joint action agency representing 134 members, routinely explores beneficial electrification opportunities to help its member utilities with load growth while addressing peak demand on the grid. VEIC, a non-profit organization aiming to reduce the economic and environmental costs of energy use, approached AMP about forming a partnership to study the potential for grid-interactive HPWHs in AMP member communities. AMP was eager to collaborate with VEIC and move forward with the study with the help of grant funding by the American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program.

AMP’s Assistant Vice President for Energy Policy and Sustainability, Erin Miller, played a key role and served as the project manager for AMP. She worked with VEIC, AMP’s cross-departmental team, and its members to develop the work products. 

During the project, Miller appreciated collaborating with her team and hearing from AMP members. 

“It was definitely a group effort, we had several members providing us guidance, and staff across departments were engaged,” Miller said. “VEIC was a great partner; we worked with Emily Lewis O’Brien and Chris Badger, and we built off of previous work conducted by Hawaii Energy and Environmental and Energy Study Institute (EESI).” 

Prior to the start of the project, the team had three goals according to Miller. They wanted to study the market potential of HPWHs in AMP’s members’ service territory, develop guidance and a program for public power utilities wishing to learn more about the technology, and develop a tool for utilities to discover what their customers’ economic and environmental benefits would be if customers switched to a grid-interactive HPWH from an electric-resistance, natural gas, oil, or propane-powered water heater.   

The Grid-Connected Heat Pump Water Heater (HPWH) Guidebook contains an introduction to HPWHs, HPWH control, service provider options for HPWH control, and HPWH program case studies. 

“The Guidebook developed in this project contains a wealth of information for utilities on grid-interactive HPWHs,” Miller said. “In particular, utilities with a high percentage of customers with electric resistance water heating have the greatest peak-saving potential from adding grid-connected HPWH, while utilities with a high percentage of customers with oil/propane water heat can add new load from grid-connected HPWH with minimal peak impacts.” 

The Guidebook also helps develop recommendations to maximize benefits for both customers and utilities by addressing market opportunities and barriers and offering best practices for program design, equipment installation, and utility integration into demand response programs.  

Miller said the Excel-based Grid Connected Heat Pump Water Heater Calculator Tool is designed to assess the customer economics for installing a HPWH under different scenarios and geographic locations. Component information on fuel costs, etc. is supplied for 10 towns in AMP’s region; other users can add their own town’s energy cost data to use the tool. 

Together, the Guidebook and Calculator can help public power utilities understand both the opportunity and options for offering a grid-connected HPWH program in their territories.  

DEED members can learn more about the project in the DEED Project Library. Additional details about the DEED program are available here. 

Louisville, Ky., Eyes Municipalization, Seeks Consultant For Study

February 16, 2022

by Paul Ciampoli
APPA News Director
February 16, 2022

The Louisville/Jefferson County Metro Government is seeking proposals for a municipalization feasibility study.

In early 2020, Louisville Metro Mayor Greg Fischer formally signed Louisville Metro Resolution No. 0009, Series 2020, in which the Louisville Metro Legislative Council resolved to support, among other things, a 100 percent clean, renewable electricity goal for Louisville Metro government operations by 2030.

“Louisville Metro is exploring a variety of supply- and demand-side pathways to achieve this goal, attempting to gather unbiased and decision supportive information to inform next steps to pursue this goal,” the RFP for the study noted.

In an interview with Public Power Current, Allison Smith, Assistant Director, Office of Advanced Planning and Sustainability at Louisville Metro Government, noted that in order to achieve the 100 percent renewable energy goal, “we partnered with” the National Renewable Energy Laboratory (NREL).

In the first phase of working with NREL, “we spent about a year going through what our possible options are to reach our goal,” she said.

Smith noted that Kentucky is in a vertically integrated energy market. “We have a regulated monopoly,” with an investor-owned utility, Louisville Gas & Electric (LG&E).  

“We are not able to contract for renewable energy directly with a company. We have to go through our local utility. That really is limiting,” she said.

“NREL helped us identify what are the routes that we could get to our goal,” Smith said.

“We are now entering phase two. We’ve identified three possible routes.”

One route would be entering a virtual power purchase agreement or purchasing renewable energy credits. “That is certainly an option, but for a local government, that is purely a financial transaction, so there is some risk involved, especially with a virtual power purchase agreement, depending on how the market goes. And really that would not get us any of the local benefits that we are looking for in our transition to renewable energy,” Smith said. “We took that one off the table for now.”

A second option is to work with LG&E. Smith noted that large customers of LG&E can enter into a special contract with the utility “where they will build solar on your behalf and then that large customer negotiates a rate with LG&E that’s locked in for usually twenty years.”

Smith said that “we are working with NREL and LG&E to go through what would the criteria for this special contract have to be for it to make sense and for it to work for Metro Government. We’re talking about taxpayer dollars, so we do have to be financially responsible with that while still meeting our goals.”

The third option is municipalization.

Louisville Metro has identified the possibility of pursuing a partial municipalization of the Louisville Gas & Electric-owned distribution network which serves some or all of the municipal electric load. Louisville Gas & Electric is a subsidiary of investor-owned PPL Corp.

This partial municipalization would involve creating a new municipal electric utility to provide electricity service exclusively to municipally-owned and operated buildings.

In order to bring this partial municipalization into reality, Louisville Metro would need to pursue an “overbuild” of new, municipally-owned electric distribution infrastructure that will co-exist on top of LG&E’s existing distribution infrastructure while not being electrically connected, the RFP said.

This new distribution network would serve some or all municipal electric load with clean energy. This pathway would also involve connecting the new distribution network via a short, high voltage transmission line to the Midcontinent Independent System Operator, “and procuring clean, affordable and reliable electricity through existing market mechanisms (e.g., spot or day-ahead markets) and/or long-term power purchase agreements,” the RFP said.

Overall, the consultant will organize a partial municipalization cost analysis into two major demand scenarios:

The RFP is available here.

New Mexico Utility Regulators Says Legislature Is Best Suited For Public Power Study

February 16, 2022

by Paul Ciampoli
APPA News Director
February 16, 2022

In a recent letter to lawmakers in New Mexico, commissioners with the New Mexico Public Regulation Commission (PRC) said that the New Mexico Legislature, and not the PRC, is the proper body to conduct a study that would evaluate shifting the state’s electric sector to public power.

A group of New Mexico lawmakers recently asked the PRC to launch a study that would evaluate shifting the state’s electric sector to public power. The PRC subsequently held a hearing related to the petition from the lawmakers.

PRC Commissioners sent a letter on Feb. 3 to several New Mexico lawmakers in which the state utility regulators responded to the idea of the PRC conducting the study.

In the letter, the Commissioners said that after reviewing New Mexico House and Senate Memorials (SM 10/HM 20) related to the study, the PRC “takes no position on the merits of a state-level public utility for New Mexico. We believe that is the proper purview of the Legislature.” 

Memorials introduced in the New Mexico do not have the force of law. Memorials can be either joint or simple and require no action on the part of the governor. Joint memorials are acted on by both houses.

The state utility regulators said they have concerns about the proposed role of the Commission in the study and suggested that the stated goals of the memorials would be better served if it were conducted by the Legislature in cooperation with an outside entity.

The PRC is particularly concerned that the role proposed for it is potentially an improper one for it to fulfill.

“We do not believe that the Commission has authority over the subject matter of the study, nor should it exercise authority given its regulatory responsibilities,” the Commissioners said.

“The statutes delegating responsibility to the Commission, particularly the Public Utility Act, implicitly presuppose the existing electric service landscape of investor-owned utilities and member-owned rural electric cooperatives and direct the Commission to regulate accordingly,” the letter noted.

The New Mexico Public Regulation Commission Act’s “apparent limitation on the Commission’s power to study/investigate, suggests that it should not conduct a study the results and recommendations of which the Commission would be unable to act upon. 

Because the results and recommendations of the studies envisioned in SM 10 and HM 20 “can only be acted upon by the Legislature, a study conducted by the Legislature, independent of the Commission but with the Commission providing data and other information under its control, would be more appropriate,” the letter went on to say.

Putting aside whether, under the current statutory framework, participating in the study is a permissible activity for the Commission, the PRC Commissioners raised a number of additional concerns and questions.

The Commissioners pointed out that the PRC’s primary statutory responsibilities are to adjudicate matters to which the utilities are parties and to issue regulations to which the utilities are subject. 

“Having the Commission potentially advocate for or against a state-level public utility before the Legislature, making recommendations either in agreement with or in opposition to the utilities it regulates would, at the very least, raise the possibility of unresolvable conflicts of interest for the Commission when presiding over future matters to which the utilities are parties.”

California 300-MW Energy Storage Facility Goes Offline

February 16, 2022

by Paul Ciampoli
APPA News Director
February 16, 2022

A 300-megawatt (MW) energy storage facility in California is offline at the same site where another storage facility went offline last year.

Late on February 13, the early detection safety system activated in the 100-MW Phase II building at Vistra’s Moss Landing Energy Storage Facility, Vistra reported.

“As is our protocol at all of our facilities, we contacted off-site emergency response out of an abundance of caution. The building’s systems contained the event without the need for the outside assistance. There are no injuries to personnel. An investigation is underway to determine what caused the safety system to activate,” the company said.

While this is in its very early stages, “what we know is the water-based suppression system released water that contacted some batteries.”

Vistra said that there is early evidence that water hoses leaked and that some batteries shorted, creating smoke in the building, similar to what was observed with a September 2021 incident at Vistra’s 300-MW Phase I facility next door.

The suppression system contained the event, and the 100-MW Phase II system is currently offline.

The Phase I facility was not affected by Sunday’s incident. “We have been in the process of incrementally bringing the Phase I facility back online but have decided to pause restart activities while we assess the Phase II incident and will incorporate any learnings,” the company said.

DOE Establishes Infrastructure Law’s $9.5 Billion Clean Hydrogen Initiatives

February 16, 2022

by Paul Ciampoli
APPA News Director
February 16, 2022

The U.S. Department of Energy (DOE) recently announced two requests for information (RFI) to collect feedback from stakeholders to inform the implementation and design of the infrastructure law’s Regional Hydrogen Hub and the Electrolysis and Clean Hydrogen Manufacturing and Recycling Programs.

The law includes:

The RFIs will gather input from a range of stakeholders, including regional leaders, local groups, environmental justice community members, researchers, technology developers, businesses among others to inform the design of clean hydrogen programs, DOE said.

Topics under the Hydrogen Hubs Implementation Strategy RFI include solicitation process, funding opportunity announcement structure, and implementation strategy; equity, environmental and energy justice and priorities; and market adoption and sustainability of the Hydrogen Hubs.

Topics under the Clean Hydrogen Manufacturing, Recycling, and Electrolysis RFI include manufacturing and supply chain of clean hydrogen equipment and components; approaches to recycle hydrogen end use technologies including fuel cells; and development, testing and integration of electrolyzers. 

Feedback received from these RFIs will also support DOE’s Hydrogen Shot efforts to cut to cost of clean hydrogen to $1 per 1 kilogram in one decade.  

Click here for the RFIs.

Click here for resources and opportunities for public power tied to the infrastructure law curated by the American Public Power Association.

Electric Utility Board Votes In Favor Of Lubbock Power & Light Transition to Retail Competition

February 16, 2022

by Paul Ciampoli
APPA News Director
February 16, 2022

The Electric Utility Board for Texas public power utility Lubbock Power & Light (LP&L) on Feb. 15 voted in favor of transitioning LP&L to the competitive electric market in Texas, paving the way for Lubbock to once again have retail electric competition.

The Electric Utility Board vote was the first in a two-step approval process required for LP&L to begin the necessary work to move to retail competition.

Should the City Council also vote in favor at next week’s regularly scheduled meeting, LP&L hopes to transition to competitive retail electric service in late 2023. This would mark the first time a municipally owned utility voluntarily deregulated since Texas Senate Bill 7 first became law in 1999.

Under retail electric competition, LP&L would no longer serve as the city-owned electricity provider. Instead, customers could “shop” from multiple retail electric providers, each offering their own plans, pricing and contract terms. The retail providers would be responsible for buying and selling power, while LP&L would continue to own and maintain all transmission and distribution infrastructure, such as poles and lines.

In 1999, Texas legislators signed Senate Bill 7 into law, aimed at allowing retail electric providers to compete for customers and thereby provide Texas residents with the best possible electric rates and plans to meet their unique needs.

Lubbock residents once had a version of retail electric competition in which customers could choose between two electric providers — LP&L and SPS. In 2010, the City of Lubbock purchased distribution assets from SPS to become the sole electric provider for the majority of Lubbock residents.

The two systems were evenly distributed throughout the city since both companies served customers in nearly every neighborhood, referred to as alley-by-alley competition. Since the time of the sale, LP&L managed both systems, but they were not combined. LP&L took the first step to combine the systems in May 2021, migrating 70% (approximately 83,000 customers) of its system to the Electric Reliability Council of Texas (ERCOT).

LP&L hopes to migrate the remaining 30% (about 24,000 customers) to ERCOT in summer 2023, to get all LP&L customers in the same grid.

LP&L worked closely with the Electric Utility Board and Lubbock City Council to develop a responsible path to retail electric competition, it noted.

Rather than offer customer choice to just 70% of LP&L’s customer base currently in the ERCOT system, the current plan is to transition in late 2023, once all customers can participate.

Texas Cold Snap Peak Comes Close To A Year Ago, But Grid Holds Steady

February 15, 2022

by Paul Ciampoli
APPA News Director
February 15, 2022

During the recent cold snap in Texas, demand for electricity in the Electric Reliability Council of Texas (ERCOT) peaked at 68,862 megawatthours (MWh), slightly below the peak demand of 69,215 MWh during a February 2021 winter storm that caused widespread power outages in the state, the Energy Information Administration (EIA) reported.

“However, this winter’s peak was still below the demand ERCOT forecast for February 2021 before widespread outages began, which resulted in lower actual demand than forecast,” EIA said.

This winter, demand on the peak day of February 4 was much lower than ERCOT’s day-ahead forecast, largely because temperatures were warmer than predicted.

“Unlike in February 2021, this winter’s storm didn’t cause major declines of natural gas production in Texas, and natural gas-fired power plants in Texas maintained their fuel supply during the cold weather,” EIA said.

In February 2021, weather-related production issues reduced peak natural gas production by 16 billion cubic feet (Bcf), according to data from IHS Markit, compared with a 3 Bcf decline in peak dry natural gas production this winter.

In addition, renewable generators, largely wind, maintained a high level of output during the coldest periods this winter, when demand for space heating was the highest, according to EIA.

Coal-fired and nuclear units did not experience outages, which occurred in February 2021.

In response to the ample supply, the ERCOT prices for wholesale electricity in the real-time market were below $100 per MWh during the recent storm, in comparison to prices that were as high as $9,000 per MWh during the February 2021 storm.

ERCOT Reforms

ERCOT in early February noted that it has implemented many reforms to increase the reliability of the Texas grid, including: